1. Field of the Invention
The present invention relates to a process for the elimination of hydrogen sulfide from oil shale. Further, this process facilitates subsequent removal of arsenic from product oil produced in a oil shale retort.
2. Description of the Prior Art
Shale-oil deposits in the United States occur over a wide area with the most extensive in the Devonian-Mississippian shales of the United States. Additional deposits are present in the Green River Formation of Colorado, Utah and Wyoming. These vast deposits offer an important potential reserve of hydrocarbons in the face of the eventual depletion of conventional sources of oil. Various methods, such as, retorting and pyrolysis are used to remove oil and other hydrocarbons from shale. Various other techniques that are used commercially are illustrated in Kirk-Othmer, Vol. 16, pp. 333-352 (John Wiley and Sons, New York). However, air pollution in the form of gases containing sulfur, nitrogen oxides, carbon monoxides and trace elements are serious problems that result from these techniques.
Eastern shales of the United States are known to contain pyrite. Some eastern shales contain significant amounts of pyrite resulting in the production of copious amounts of hydrogen sulfide during any retorting process or thermal conversion process.
In some shales, such as the New Albany shales of Kentucky, Ohio and Indiana, the amount of hydrogen sulfide produced upon retorting could represent 20 percent of the products. Because of the nature of oil shale retorting, the gaseous products are difficult to separate from the liquid products. Usually the product of retorting is a mist which has to be condensed to provide an oil fraction and a gaseous fraction.
As generated, the gas from shale retorting contains hydrogen sulfide, droplets of oil that were not condensed by the oil recovery system and all the non-condensable compounds formed during the retorting process. Usually the gas generated during a shale oil retorting operation is a fuel source for the retorting process. With the current environmental concerns, fuels containing sulfur are not acceptable unless their sulfur is reduced to acceptable levels. For example, the current sulfur specifications for natural gas dictate a hydrogen sulfide content of less than 0.5 percent by weight. Clearly, the use of the gas generated in most shale oil retorting is not acceptable without a hydrogen sulfide removal procedure.
One of the most efficient and commercially applicable processes for the removal of hydrogen sulfide is the alkanolamine process. In this process, sour gas, with a minimum amount of condensable hydrocarbons, is reacted with an alkanolamine to form an alkanolamine hydrogen sulfide salt and a hydrogen sulfide-free gas. If condensables are present in the gas stream being treated, process difficulties, such as, foaming and severe temperature fluctuations, result. Thus, to minimize processing difficulties in the hydrogen sulfide removal operation it is be desirable to have a condensable-free gas feed. In any oil shale retorting process this is very difficult to achieve. Thus, treating the gas generated in an oil shale retorting process without removing the condensables results is a downstream problem which has to be addressed.
Heretofore, it has been recognized that it would be highly desirable to eliminate or substantially eliminate the pyritic content of shale thereby minimizing the hydrogen sulfide content of the gases from oil shale retorting. In this regard, a number of processes have been suggested for reducing pyritic sulfur in shale.
For example, it is known that some pyritic sulfur can be physically removed from shale by grinding the shale or subjecting the shale to froth flotation or washing processes. While such processes may be desirable for the removal of pyritic sulfur from shale, they are not fully satisfactory because a significant amount of the pyritic sulfur is not removed. Attempts to increase the portion of pyritic sulfur removed have not been successful because these processes are insufficiently selective and can result in a large portion of the shale being discarded along with the pyrite.
In view of this difficulty, chemical treatment of sour gas has been employed in an effort to reduce the hydrogen sulfide content and to ultimately reduce pollution caused by this gas.
The most commercially used process involves the use of monoethanolamine or diethanolamine in an aqueous solution to absorb hydrogen sulfide and carbon dioxide from sour gas. The basic design includes an absorber in which a lean water solution of either alkanolamine absorbs the acid gases (hydrogen sulfide and carbon dioxide) from the sour gas and a stripper in which heat, usually in the form of steam, separates the acid gases from the pregnant amine solution.
U.S. Pat. No. 4,461,754 to Zaida describes another approach for the removal of hydrogen sulfide and carbon dioxide from a variety of gas streams. The gas stream containing the sour gas is contacted with an aqueous solution of a specific reactant ligand or chelate, or mixtures thereof, optionally in an absorbent which contains specific stabilizers for improvement of ligand life. The hydrogen sulfide is converted to sulfur, CO.sub.2 is absorbed to produce a purified gas stream, and the reactant ligand is reduced.
U.S. Pat. No. 4,400,361 to Shafer describes a process for the removal of hydrogen sulfide from sour gas streams. Accordingly, sour gas is passed in concurrent flow relationship with a liquid alkaline absorption solution containing a vanadium-boron complex characterized by reacting liquid alkaline solution with the H.sub.2 S thereby oxiding (HS--) to elemental sulfur in conjunction with reduction of the vanadium, while the boron constituent is functional to inhibit formation of insoluble vanadium sulfide compounds. Regeneration of the absorption medium by contact with an oxygen-containing gas is enhanced by the provision of an iron-polyamine organic acid oxidation catalyst in the absorption liquid.
U.S. Pat. No. 4,395,385 to Welsh describes a process for removing hydrogen sulfide from sour gas. This process comprises contacting a sour gas stream with an aqueous alkali metal hydroxide solution containing a stoichiometric excess of the alkali metal hydroxide to provide a sweet gas substantially free of hydrogen sulfide and a partially spent aqueous alkali metal solution. The partially spent aqueous alkali metal solution is contacted with a second sour gas stream in a countercurrent fashion to provide a second sweet gas and a substantially caustic-free aqueous solution of the alkali metal hydrosulfide.
U.S. Pat. No. 4,401,642 to Bleztas, et al., describes a process for sweetening sour gas. The process is characterized by the conversion of H.sub.2 S to sulfur employing specific aqueous solution reactants. The sulfur is recovered by employing known frothing and extraction techniques.
While the art has provided a number of processes for the removal of hydrogen sulfide from gases produced upon oil shale retort, there still exists a present need for a practical method to more effectively reduce or eliminate the hydrogen sulfide from gases produced from oil shale.
Accordingly, it is one object of the present invention to provide a process for the elimination of hydrogen sulfide from gases produced from oil shale retorting.
It is another object of this invention to provide a method for the substantial reduction of arsenic from product oil obtained from oil shale retorting of oil shale.
The achievement of these and other objects will be apparent from the following description of the subject invention.